Because of the expense of offshore oil and gas drilling, most wells have sufficient internal formation pressure to flow naturally. However, the internal formation pressure declines as the well fluid is produced over time. Consequently, there are subsea wells that have been shut in because the internal pressure was not adequate. Also there are subsea wells that continue to produce but at a rate below their actual potential. The reduction in production is due not only to a decline in reservoir pressure, but also because of an impairment of the reservoir and/or an increase in fluid gradient. One or a combination of these factors can render the well unable to produce fluid to the processing facility. This is particularly a problem in very deep water where even if the pressure at the wellhead is positive, it may be inadequate to flow the reservoir fluid to a floating production vessel at the surface.
Proposals have been made to install pumps adjacent to or on the production tree. Also, it has been proposed to install electrical submersible pumps (ESP) in nearby specially drilled caissons, which are shallow bores drilled into the sea floor. It has also been proposed to install an ESP in a production riser section extending from the subsea well to the production vessel. Another proposal involves installing an ESP within the production tubing after the reservoir pressure declines.
For safety, if a well is live or has positive pressure at the wellhead, the well is killed before lowering the ESP into the well. Killing the well typically involves pumping a heavy fluid into the well to prevent an accidental blowout while the ESP is being lowered into the well. However, killing a well can cause damage to the formation from the kill fluid. After killing the well, it is possible that the well may not again return to its former pressure level. Because of the risk, killing a live subsea well to install an ESP is not normally done. There have also been proposals to install ESPs in live land wells using various techniques, but these proposals are not easily applicable to subsea wells with subsea production trees.
General safety rules require that a well have at least two pressure barriers at all times, even when undergoing a workover. During its natural reservoir drive, the well fluid is normally produced through tubing that is suspended in the wellhead assembly at the sea floor surface by a tubing hanger. The tubing hanger seals within the wellhead assembly or production tree to provide one pressure barrier. Normally, there will be at least one other structure, such as a tree cap, to provide an additional safety barrier during production.
For offshore wells, downhole safety valves are installed a relatively short distance below the sea bed within the production tubing. A downhole safety valve is a type of valve that is biased closed and held open with hydraulic fluid pressure. If the hydraulic fluid pressure fails, the valve will close. Consequently, in the event that the wellhead assembly is damaged, or if the hydraulic fluid pressure is lost, the valve will close.
While a closed downhole safety valve could serve as a second pressure barrier during the installation of an ESP, the valve would have to be open when the ESP passes through it. Normally, ESPs are located deep within the well, far below the downhole safety valve and just above the perforations leading to the reservoir so as to achieve the most efficient production boost.